Assessing reservoir heterogeneity using the turbulence factor as an effective tool for hydraulic flow unit classification for BM-85 Well, Gulf of Suez, Egypt

This study provides a detailed investigation into reservoir heterogeneity within the Lower Senonian Formation of the BM-85 well, Gulf of Suez, through the integration of core analyses, well-log interpretation, and advanced heterogeneity characterization techniques. Reservoir heterogeneity, driven by depositional environments, diagenetic alterations, and structural evolution, was shown to exert a fundamental control on porosity–permeability distributions, fluid flow behavior, and overall reservoir performance. Well-log interpretation, supported by litho-saturation crossplots, successfully delineated two pay zones. Pay 1 is characterized by moderate porosity (21%) and hydrocarbon saturation (63%), while Pay 2 exhibits excellent reservoir quality with an average permeability of 716.3 mD, effective porosity of 18–21%, and hydrocarbon saturation of 44%. The strong consistency between core-derived parameters and log-based interpretations highlights the robustness of the integrated workflow. Petrophysical evaluation from core analysis revealed wide ranges of porosity (11–33%) and permeability (0.1–6431.82 mD), reflecting strong lithological and textural variability. The Dykstra–Parsons coefficient (V = 0.91) confirmed extreme heterogeneity, indicative of pronounced contrasts in permeability and pore-throat distribution. The integration of Reservoir Quality Index (RQI) with the turbulence factor (β) allowed classification of Hydraulic Flow Units (HFUs), successfully distinguishing high-quality reservoir zones with well-connected pore networks from tighter, flow-restrictive intervals. Cross-plots of porosity versus permeability further demonstrated the strong influence of pore structure, diagenesis, and clay content on flow efficiency, emphasizing the role of secondary controls in governing reservoir performance. Mercury Injection Capillary Pressure (MICP) measurements provided additional insights into pore-throat radii (r 35 ) and allowed classification into distinct reservoir quality groups ranging from tight to highly productive. Flow–storage capacity relationships, analyzed using the modified stratigraphic Lorenz technique, confirmed that high-permeability streaks disproportionately contribute to flow capacity, underscoring the complexity of fluid distribution in heterogeneous systems. Overall, the study demonstrates that reservoir heterogeneity in the Gulf of Suez is controlled by the interplay of depositional, diagenetic, and structural processes. Quantitative tools such as the Dykstra–Parsons coefficient, RQI–β cross-plots, and pore-throat classification provide powerful means of assessing heterogeneity, classifying flow units, and predicting reservoir behavior. These findings highlight the importance of integrating core, log, and laboratory data to improve reservoir characterization and guide optimal field development strategies. Understanding the spatial distribution of heterogeneity is critical for enhancing recovery efficiency, managing waterflooding operations, and accurately forecasting reservoir performance in one of Egypt’s most structurally complex petroleum provinces. Permeability, heterogeneity, and the reservoir quality index have a major effect on the turbulence factor, a useful indicator for reservoir zonation based on flow properties. Additionally, the distribution of pore throat sizes has a positive/negative effect on the flow system; the more macropores there are, the higher the permeability and lower the turbulence factor, and the more micropores there are, the lower the permeability and higher the turbulence factor. Finally, Pay Zone 1 corresponds to HFU-1 (Group A), characterized by moderate porosity and permeability, while Pay Zone 2 aligns with HFU-2 (Group B), exhibiting higher reservoir quality and flow capacity. This correlation highlights the consistency between log-based and core-based analyses, providing a more integrated understanding of reservoir heterogeneity and reinforcing the relevance of HFU classification in delineating productive intervals. We now emphasize that reservoirs dominated by macropores exhibit lower turbulence factor (β) values, reflecting more efficient flow behavior, whereas tighter pore systems are associated with higher β values and increased non-Darcy flow effects.